For finding petroleum fluids in geological strata the seismic method is the prime method. Seismic signals are generated at the surface and propagate downward and are partly reflected by every seismic impedance contrast. Seismic impedance is the product of seismic acoustic velocity and density. The seismic signals are acquired by a series of seismic sensors after having been reflected, and the time series collected at a seismic sensor for each seismic transmission from the seismic source is called a seismic trace. For monitoring or controlling the development of the fluid content of the geological strata during petroleum fluid production so-called time-lapse seismic data are conducted during the life of the petroleum field. Material changes within the geological strata may cause changes of the local seismic impedance and may be seen as a time shift between seismic data acquired at different times during petroleum production. Knowing parameters about the material changes of the geological strata may provide key information to how to control the petroleum fluid production such as adjusting the production rate of gas or petroleum, adjusting the depth of which petroleum fluids are produced, or determining injection rates of gases or fluids in order to support the petroleum fluid production.
U.S. Pat. No. 6,574,563 describes a non-rigid method of processing a first and a second seismic data set acquired from the same underground area. The method is referred to as the “NRM method”. The NRM method comprises arranging the first and the second seismic data sets into sample sets, generating displacement vectors that indicate a direction and an amount for each sample individually from one data set may be moved to improve the match with corresponding samples from the other sample set. The process is completed by conducting the suggested move of one of the set of samples. The method has the advantage that differences between first and second seismic time sets that may be explained by noise may be attenuated, such as noise due to different source characteristics, differences between the acoustic sensors in the streamers used, positioning and depth differences for the source and the seismic streamers, data acquisition differences, and different processing. In a basic embodiment the method may be constrained to only suggest and conduct vertical movement of samples, as a good match may almost always be obtained if one tries to correlate samples along a seismic reflector.
A condition for the so-called NRM method to work well is that counterparts actually exist for generally all samples of both seismic data time sets to be compared. Seismic events that have no significant counterpart may incur the method trying to move a seismic event comprised by a group of samples, say, a new seismic horizon in one of the seismic data time sets, to better fit a seismic event actually not occurring in another seismic data time set, and thus forcing the displacement of other seismic events in the seismic data time set in an inappropriate way.
The methods which have been developed previously for matching time shifted seismic data may be significantly improved in order to provide an even better match of seismic traces. Further, background art methods have little tolerance for new seismic events, as the matching process may force non-relevant matching onto the seismic data while locally forcing a displacement of otherwise matching parts of time shifted seismic data.